distribution investment plan - s3. · pdf file3.7. business intelligence and data analytics...
TRANSCRIPT
______________________________________________________________________________
BEFORE THE
PUBLIC SERVICE COMMISSION
OF MARYLAND
IN THE MATTER OF THE APPLICATION OF )
BALTIMORE GAS AND ELECTRIC COMPANY ) CASE NO. 9406
FOR ADJUSTMENTS TO ITS ELECTRIC )
AND GAS BASE RATES )
DISTRIBUTION INVESTMENT PLAN
June 5, 2017 ______________________________________________________________________________
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TABLE OF CONTENTS
1. INTRODUCTION ................................................................................................................. 1
2. ELECTRIC SYSTEM INVESTMENT PLANNING PROCESS ..................................... 2
2.1. Capital Planning Process ......................................................................................................... 3
2.2. Types of BGE Project Categories ........................................................................................... 6
2.3. Project Identification ............................................................................................................... 6
2.3.1. Major Capital Projects .............................................................................................. 7
2.3.2. Short Lead Projects ................................................................................................... 7
2.3.3. Long Lead Projects ................................................................................................... 7
2.4. Capacity Expansion – Distribution .......................................................................................... 8
2.4.1. Load Forecasting ....................................................................................................... 8
2.4.2. Contingency Analysis ............................................................................................. 10
2.4.3. Distribution Circuit Analysis .................................................................................. 11
2.4.4. System Voltage Planning and Analysis .................................................................. 11
2.4.5. New Business and Steady State Load Growth ........................................................ 12
2.4.6. Demand Response Programs .................................................................................. 13
2.4.7. Distribution Planning Process Data and Future Impacts of AMI ........................... 14
2.5. Capacity Expansion – Transmission ..................................................................................... 15
2.5.1. Transmission Planning Impacts from AMI............................................................. 16
2.6. System Performance .............................................................................................................. 17
2.6.1. AMI Impact on System Performance ..................................................................... 17
3. USE OF THE AMI SYSTEM TO FURTHER IMPROVE THE EFFICIENCY AND
EFFECTIVENESS OF THE DISTRIBUTION NETWORK ......................................... 18
3.1. BGE PeakRewardsSM
Enhancement Program ............................................................ 18
3.2. Remote Meter Reading and Remote Connection ....................................................... 19
3.3. Outage Management System – AMI System Integration ...................................................... 19
3.3.1. Restoration Verification .......................................................................................... 20
3.3.2. Automatic Restore Time Adjustment and Predicted Service Outage Verification. 21
3.3.3. OMS Functionality Currently Being Tested ........................................................... 21
3.4. Energy Theft Program ........................................................................................................... 22
3.5. Distribution Automation ........................................................................................................ 22
3.5.1. DA Communication System – Leveraging the AMI Provider System ................... 23
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3.6. Conservation Voltage Reduction ........................................................................................... 24
3.7. Business Intelligence and Data Analytics ............................................................................. 24
3.7.1. Transformer and Line Equipment Sizing ................................................................ 25
3.7.2. Power Quality Assessment ..................................................................................... 26
3.7.3. Network Connectivity ............................................................................................. 26
3.7.4. Load Forecasting ..................................................................................................... 28
3.7.5. Overloaded Equipment Transparency ..................................................................... 29
3.7.6. Momentary Data Analysis ...................................................................................... 29
3.7.7. Voltage Var Optimization ....................................................................................... 30
4. USE OF THE AMI SYSTEM TO FURTHER IMPROVE THE EFFICIENCY AND
EFFECTIVENESS OF DISTRIBUTED ENERGY RESOURCES
INTERCONNECTED TO THE DISTRIBUTION NETWORK .................................... 30
4.1. DER System Impact Challenges ................................................................................. 32
4.2. Benefits of DER.......................................................................................................... 33
4.3. Smart Inverters ........................................................................................................... 33
4.4. Energy Storage ........................................................................................................... 34
4.5. Benefits of AMI for DER ........................................................................................... 34
5. CONCLUSION .................................................................................................................... 35
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1. INTRODUCTION
By Order No. 87591 dated June 3, 2016, the Maryland Public Service Commission (the
“Commission”) authorized recovery of certain costs Baltimore Gas and Electric Company
(“BGE”) incurred in deploying its Advanced Metering Infrastructure (“AMI”) system. In so
doing, the Commission found “compelling evidence that BGE’s AMI system is cost beneficial to
its customers.”1 One of the many benefit streams considered by the Commission in its cost-
benefit analysis was avoided transmission and distribution (“T&D”) capital expenditures. The
method proposed by BGE for valuing avoided T&D was the marginal cost approach approved by
the Commission in Case No. 9154 (EmPOWER Maryland), Order No. 87082, on July 16, 2015.
The Commission accepted this methodology for valuing the AMI system-enabled avoided T&D
capital expenditures, but it also required that BGE file a distribution investment plan within
twelve (12) months of the date of Order No. 87591.2 With respect to the contents of the
distribution investment plan, the Commission stated as follows:
The required Plan shall analyze in detail the Company’s strategy over the next
five years for investing in its distribution system and shall include, among other
things, specifics about how the Company’s investment in smart meters will be
utilized to improve the efficiency and effectiveness of the distribution network.3
As detailed in this Distribution Investment Plan (the “Plan”),4 BGE maintains a robust
and ongoing process to identify and prioritize required investments on its distribution system.
BGE considers a number of factors in determining whether to make a particular investment on
the distribution system, including age of infrastructure, reliability history, forecasted load
1 MDPSC Case No. 9406, Order No. 87591 at pp. 2-3 (June 3, 2016).
2 Id. at pp. 57-58.
3 Id. at p. 58.
4 Although this is a “distribution” investment plan, BGE has also provided certain information in this Plan about
system planning processes and programs relevant to the “transmission” system.
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growth, and available generation, distributed energy, energy efficiency, and demand response
resources and programs. The data produced from the AMI system will increasingly enable BGE
to analyze system conditions more precisely and tailor its distribution system investments
accordingly.
Over the course of the next five years, BGE will pursue opportunities to use its AMI
system to optimize insights into customer behavior, distribution system equipment performance,
and system load growth/reduction. For example, BGE will be deploying new business
intelligence/data analytics (“BIDA”) tools to manage and process the large quantities of data
produced from the AMI system. Access to these BIDA tools will help BGE to better plan for
and design system improvements, thus increasing the overall efficiency and effectiveness of the
distribution network and the electric service that BGE provides to its customers.
In addition, BGE will continue to promote and expand its core AMI-enabled programs,
BGE Smart Energy Manager® (“SEM”) and BGE Smart Energy Rewards
® (“SER”), and develop
additional AMI-enabled programs that will help customers monitor and control their usage.
Importantly, AMI-enabled programs like SEM and SER that lead to predictable reductions in
customer load may avoid certain upgrades on the distribution system that would otherwise be
necessary absent the existence of such programs. Finally, BGE plans to investigate and develop
additional AMI-enabled opportunities that will allow customers to better take advantage of
modern technologies such as electric vehicles, energy storage, and distributed energy resources
(“DER”).
2. ELECTRIC SYSTEM INVESTMENT PLANNING PROCESS
BGE undertakes a 5-year planning process to identify and prioritize required distribution
system investments. The objective of this planning process is to ensure that adequate
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infrastructure exists to reliably supply electric service for all customers at the lowest overall cost,
consistent with goals regarding safety, reliability, quality of service, community relations, and
protection of the environment. As part of this process, BGE reviews its 5-year project plan to
verify the service dates of projects needed to supply customer load or address system
performance issues. As system conditions change, projects may be expedited or deferred. This
planning process is improved by BGE’s AMI system data. The AMI customer load information
is more granular and provides a greater understanding of the impact of customer participation in
AMI-enabled programs. As later described in this Plan, incorporation of this AMI data into the
investment planning process will enable BGE to better prioritize its required distribution system
investments and expenditures in a manner that maximizes customer reliability benefits and
satisfies the capacity expansion requirements of the system.
2.1. Capital Planning Process
Fundamental to every capital planning process are the underlying studies and analyses
that serve as the basis and justification for the investment decisions. To that end, the planning
process at BGE includes comprehensive system studies and detailed analyses of the electric
distribution and sub-transmission systems “radially” supplied from the bulk power system.
Studies of the network transmission system are also conducted as part of the regional
transmission system planning process. Additionally, reliability analyses are performed to
identify and mitigate reliability concerns associated with changing system conditions or aging
infrastructure.
These studies and analyses have the overarching objective to proactively identify
potential issues that impact BGE’s ability to supply customer load. Thermal, voltage, aging
infrastructure, and reliability issues are typically the drivers for projects. A thermal issue occurs
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when the capacity of equipment is exceeded and begins to overheat. The overheating can
quickly lead to premature failure. A voltage issue occurs when voltages are outside of prescribed
limits as outlined in Code of Maryland Regulations (“COMAR”) 20.50.07.02. Customer
equipment operating outside these limits can experience reduced equipment life, equipment
damage, and other issues. Reliability issues may occur due to vegetation growth or the changing
environment.
Many triggers exist that may create thermal or voltage issues on the electric system.
Customer load growth and expansion are some of the common causes. As developments
(residential, commercial, and industrial) are connected to the electric infrastructure, additional
equipment utilization occurs. When the excess system capacity is exhausted, additional electric
infrastructure is often needed. In addition to new customer connections, existing customers may
also experience load growth as they expand their use of electricity and the infrastructure becomes
insufficient to meet the peak usage. When a thermal or voltage violation is likely to occur,
regulatory requirements may no longer be satisfied, thus requiring prompt response from the
utility. The following Figure 1 contains the typical project threshold at BGE:
Figure 1: Potential Project Triggers – Forecast Load of Component
Potential Project Triggers
Description Threshold
13kV Circuit Overload Forecast >110% of Normal Rating
34kV Circuit Overload Forecast >100% of Normal Rating
34kV Circuit Contingency Overload Forecast >100% of Emergency Rating
Substation Transformer Overload Forecast >100% of Normal Rating
Substation Transformer Contingency Overload Forecast >100% of Emergency Rating
Firm Substation Overload Forecast >100% of Emergency Rating
Semi-Firm Substation Overload
(block circuit transfer) Forecast >100% of Emergency Rating
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Potential Project Triggers
Description Threshold
Other Operational and Reliability Issues
(circuit ties, voltage issues, operability issues) Program Determined
Other drivers for distribution investments include aging infrastructure replacement or
repeat reliability issues. As equipment ages beyond its useful life, the risk for possible failure
increases. Repeat reliability issues due to vegetation or the changing environment may also
prompt the utility to plan corrective actions. The planning process attempts to proactively
identify these issues in advance of actual need in order to allow projects sufficient time to be
built and to avoid the possibility of equipment failure or customer dissatisfaction.
BGE utilizes a mix of short-term and long-term solutions in order to cost effectively
resolve system issues. When larger increments of load are expected in the future, additional
infrastructure will be planned to avoid issue recurrence. Transferring customer load from one
circuit to another may be possible to provide a short-term, low cost solution. When load
transfers are not possible, BGE investigates replacing existing infrastructure with higher capacity
equipment. The addition of new circuits, substation transformers and entire new substations are
all considered when determining the lowest cost solution. BGE also considers innovative
alternative solutions, like DER. The following Figure 2 provides a standard timeline for the
different distribution solutions commonly employed:
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Figure 2: Project Execution Time Frames
Project Execution Time Frame
Immediate 0-1 Year 1-2 years 2-3 years 3-4 years 4-5 years 5+ years
Local Load
Control
(LLC)
Programs
Transfer Load
to Another
Feeder or
Transformer
Add Feeder Ties Build
New
Feeder
Add Capacitors
Add DA Devices
Replace Equipment With Higher Capacity Components
Build Substation
Retire/Rebuild Aging Infrastructure
2.2. Types of BGE Project Categories
BGE uses three primary categories to group its major proactive infrastructure investments
on the electric system:
1. Capacity Expansion. The Capacity Expansion category contains projects on the
distribution and transmission systems that support load growth and increase
system capacity. Projects in this category are typically infrastructure additions
needed to support customer load.
2. System Performance. The System Performance category is made up of work to
enhance system reliability through proactive equipment replacement, proactive
upgrade/restoration of existing equipment, remediation of poorest performing
feeders, implementation of industry recommendations, and replacement of aging
infrastructure.
3. New Business. The New Business category is made up of work performed to
connect new customers to the electric system. Projects to upgrade customers’
service equipment and relocate services are also included in this category.
2.3. Project Identification
BGE plans its Capacity Expansion, System Performance and New Business projects
across the service territory to address load driven and system reliability needs. These projects
fall into three subcategories: Major Capital Projects; Short Lead Projects; and Long Lead
Projects. Projects are classified into each of the categories based on a variety of factors,
including, but not limited to, execution timeline, expenditure level, and complexity of the
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project. Additionally, some projects are required by a specific time in order to meet capacity
requirements, accommodate changing system conditions, and/or accomplish reliability
objectives. For example, BGE’s electric system typically peaks in the summer months; however,
some areas of the BGE territory that lack gas service experience winter peaks due to electric
heat. To ensure projects are executed before the seasonal peaking periods, the planning process
will identify when the study area will peak (summer or winter) in order to correctly address
system issues.
2.3.1. Major Capital Projects
Major Capital Projects are typically needed to replace existing aging infrastructure
concerns on major or critical assets or address large amounts of load growth that normally come
with planned development. These types of projects are identified through the long-range
planning effort and ordinarily take several years to complete.
2.3.2. Short Lead Projects
Short Lead Projects are smaller in scope and typically executed in less than a year. For
Capacity Expansion projects, Short Lead Projects normally consist of feeder projects that are
identified by April 1st for the summer season and completed by June 1
st of the following year.
Winter projects are identified by September 1st and must be completed by November 15
th of the
following year.
2.3.3. Long Lead Projects
Long Lead Projects are medium in scope and typically executed within one to two years.
For Capacity Expansion projects, Long Lead Projects normally consist of substation or 34kV
projects that are identified by May 1st for summer and completed by June 1
st of the second year
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after identification. Winter projects are identified by October 1st and must be completed by
November 15th
of the second year after identification.
2.4. Capacity Expansion – Distribution
To ensure the electric distribution system is built for the needs of BGE’s customers, a
multistep analysis is conducted. Load forecasts are created and numerous system studies are
conducted to prioritize the proposed projects. On an annual basis, projects are reevaluated to
verify continued need. This process is designed to ensure reliability and financial objectives are
met. The following Figure 3 illustrates the process flow for BGE’s distribution planning
process:
Figure 3: Distribution Planning Process Flowchart
2.4.1. Load Forecasting
BGE develops load forecasts on the distribution and sub-transmission transformers and
feeders for both winter and summer peak conditions. The load forecast represents the best
estimate of the peak loading expected on a transformer or feeder. The forecast is based on
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existing customer load contribution (commonly referred to as the “reference load” or “base
load”), projected load growth (new customers or existing large customer expansions), planned
load transfers, and other factors that could impact loading.5 The load forecast is developed for
the next five summer and winter seasons in order to provide sufficient information to support the
5-year workload planning effort.
The time horizon for the short-range forecast – referred to as the “reference forecast” – is
one year. The reference forecast is used to support short-range project planning and also
confirms the continued need of upcoming planned projects. To account for varying weather
conditions, the reference forecast is weather adjusted and created by using a regression analysis
on the hourly loads (as illustrated below in Figure 4). In some cases, actual peaks are used
without weather adjustment, particularly for components not likely to be weather-sensitive such
as large customer feeders and sub-transmission supplied customers.
Figure 4: Summer and Winter Regression Analysis – Weather Normalize Peak Load
5 Local load control is an example of a program that impacts system loading. Under this program, BGE provides
financial compensation in exchange for the ability to control customer load. The control is used to reduce peak
loading conditions. This program was first available to large industrial and commercial customers. The program
now extends to residential customers through programs like PeakRewardsSM
and SER. DER also impact load
forecasts, but the benefit is not as straight forward as the local load control program. DER may mask native load
resulting in unexpected load increases when system failures occur, and the DER not directly controlled by the utility
may be offline when needed most.
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The time horizon for the long-range forecast is five years and beyond. The purpose of
this forecast is to support long-range planning to identify future capacity needs. Tentative dates
for major capital projects - typically substation projects - are identified through this process. The
long-range load forecast allows distribution and sub-transmission transformer and feeder projects
to be identified for future years.
A number of internal and external factors can influence the ultimate loading on BGE’s
distribution system. To account for these factors, load projections use an incremental load
growth factor, anticipated new customer additions, and planned transfers in order to develop an
understanding of the system capacity needs. The primary data sources for the long-range
forecast are the reference forecast, component loading history, energy conservation program
estimates, demand response program estimates, additional DER, land usage reports, zoning
maps, growth plans published by government agencies, and trend analysis outputs.
2.4.2. Contingency Analysis
In addition to planning for customer load during normal system conditions, BGE also
plans for unexpected failures and negative impacts to the electric infrastructure from storms and
other human or environmental impacts. BGE conducts a substation firm6/semi-firm
7 analysis
annually to determine system loading following the loss of a major piece of equipment. All firm
6 A firm substation typically serves critical load such as public safety and health, critical, and business significant
customers. Firm stations have a configuration that allows the load on one transformer to be transferred to the other
station transformer through what is called an “H-tie circuit breaker.” The customer load transfer will be automatic
for a station supply circuit, transformer, or bus failure. If mobile transformer equipment cannot be accommodated
on a site, the station will also have to follow the firm station guidelines in order to avoid long-term customer outage
impacts.
7 A semi-firm substation serves non-critical load, typically residential and small industrial and commercial
customers. Semi-firm stations have a configuration that allows the load on one transformer to be transferred to the
other station transformer through what is called an “H-tie circuit breaker.” If equipment will be overloaded by the
transfer, the circuit will not be restored following the initiating event. A semi-firm station can also accommodate a
mobile transformer, allowing all customer load to be restored within 24 hours.
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substations and semi-firm substations in BGE’s service territory are planned on a single
contingency (N-1) condition. The objective is to have a plan in place to restore all customer load
within the station following the loss of a single major component. Major components include
substation buses, switches, and transformers. The station classification – firm/semi-firm/non-
firm – determines the time frame for the customer load restoration.
2.4.3. Distribution Circuit Analysis
Prior to the summer and winter peak season, distribution circuits8 and sub-transmission
circuits9 are analyzed to determine if any thermal equipment limitations exist. When the
forecasted load on the circuits is projected to be equal to or greater than the normal rating, an
issue may exist at peak.10
An investigation is conducted to look at transferring customer load to
an adjacent circuit or building additional infrastructure to relieve any anticipated overload. The
load transfers solution identified may be permanent, seasonal, or triggered during a real time
system condition. Seasonal operating procedures are created when a solution is planned, which
may be executed in real time to address a short-term system issue. Operating procedures allow
an overload to be addressed while a long-term, permanent solution is investigated and
implemented.
2.4.4. System Voltage Planning and Analysis
In addition to ensuring adequate thermal capacity of electrical supply, BGE also plans the
system to meet voltage requirements, as outlined in COMAR. BGE performs a voltage and
8 Distribution circuits include 13kV voltage level and a supply to customer load.
9 Sub-transmission circuits include 34kV voltage level and a supply to other electric substations or large commercial
and industrial customers.
10 A “normal” rating defines the amount of power that can continually flow through a device or piece of equipment
without creating damage or loss of equipment life. An “emergency” rating defines the amount of power that can
flow through a device or piece of equipment for a short period of time and creates an acceptable amount of
equipment damage or loss of life.
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reactive power analysis twice a year to determine the number of capacitors and appropriate
capacitor settings to ensure all voltage requirements are met for the upcoming summer and
winter seasons. The analysis includes determining control scheme settings changes, non-Load
Tap Change (“LTC”)11
transformer tap adjustments, and other system changes needed to support
customer loads. New capacitors and setting adjustments are tracked as part of a seasonal
readiness activity, which are required to be completed prior to the start of the summer and winter
seasons to ensure system stability and reliability.
2.4.5. New Business and Steady State Load Growth
Load information for new customers is used to ensure that changing customer demands,
requirements, and developments are accounted for in the planning process. The data is obtained
by BGE from a variety of sources. For example, when large developments are in the initial
planning phase, property plats showing streets and building lots are submitted to BGE as a
standard practice. This information is incorporated into the planning process to ensure new
customer needs can be met along with BGE system reliability criteria.
When conducting long-range planning, BGE uses a growth factor to anticipate long-term
system capacity needs. BGE adjusts the projected year-by-year long-range peak load growth rate
on each distribution system component to align with PJM Interconnection, LLC’s (“PJM”) long-
range load forecast. The growth rate for the long-range forecast is reconciled with PJM’s long-
range forecast to ensure consistency across the distribution and transmission planning process.
While the distribution system is under BGE’s control, the systems need to be planned in
conjunction with the regional planning effort overseen by PJM.
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Transformers have a setting, or “tap,” that controls the output voltage of the equipment. A non-LTC transformer
will require an outage to change the settings. The settings are set once a season under a planned outage. LTC
transformers can have their settings adjusted in real-time with the equipment in service.
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2.4.6. Demand Response Programs
Local load control devices have been deployed on BGE’s distribution circuit and sub-
transmission circuits in order to help reduce peak energy demand and defer capacity expansion
projects. Customer load within these programs are directly controllable by the utility and allow a
direct impact on equipment loading upon program activation (see Figure 5 below). These
devices include smart thermostats and load control switches. BGE customers participate in this
initiative through the PeakRewardsSM
and AMI-enabled BGE SER programs.
Figure 5: Impact of Demand Response (LLC) on BGE Zone Load
BGE considers the impacts of its demand response programs during the forecasting and
project planning process. Demand response that is controllable by the utility is able to be used to
defer capital projects. Voluntary demand response programs, like SER, create a gradual change
in customer usage behavior. Such programs can have a sustainable impact on customer usage
behaviors over time, which could result in reduced seasonal system load forecasts. As the
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system load is affected by usage reductions due to customer behavior changes, the need for
additional system capacity may reduce or diminish. Equipment typically experiences peak load
for only a small number of hours throughout the year.
By controlling and reducing the peak loading conditions, project deferral can potentially
be achieved. An example includes the deferral of a reconductoring project two 34kV circuits
supplied out of Lippins Corner. The project was deferred by two years to 2016 from its initial
service date of 2014 based on the impact of BGE’s demand response programs. Another
example is a large substation, distribution, and transmission project in the Loch Raven area. The
project is currently being considered for deferral from 2021 to 2022 due to the impact of demand
response. The following Figure 6 depicts an example of impacts due to LCC on the project
service date:
Figure 6: Example Project Load Table Showing Project Deferral Due to LLC
2.4.7. Distribution Planning Process Data and Future Impacts of AMI
AMI is transforming the way BGE forecasts. The load values currently used in the
planning process are measured and recorded by BGE’s supervisory control and data acquisition
(‘SCADA”) system, which generally gathers data at the substations/transformer level. Customer
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monthly consumption data is used to estimate the amount of load the line equipment will see
during a given time period. Aggregate data at the substation will show the feeder loading
throughout the day. Models and the monthly customer consumption data is then used to predict
the line equipment loading near the customer. With real time metering only at the substation
level or along the circuit at key devices, the estimated load flow may not match actual loading.
A method to identify loading conditions and actual overloads on unmetered line equipment is
needed.
This load allocation process works for the current planning process, but a margin of error
exists. Integrating AMI customer data with the SCADA data can allow feeder or specific
equipment load curves to be created and analyzed. Opportunities for additional deferral of
summer and winter projects may be possible with more detailed time series12
load information.
With the addition of advanced system modeling and planning tools, AMI data will allow the
system to be modeled closer to actual conditions, resulting in improved issue identification.
Improved analysis may also allow current planning margins to be reduced allowing projects to be
built closer to the time of actual need.
2.5. Capacity Expansion – Transmission
The PJM Regional Transmission Expansion Plan (“RTEP”) process assesses the
transmission system to ensure system reliability, market efficiency, and operational performance
throughout the PJM region, which includes BGE’s service territory. PJM studies the region both
for near-term (years one through five) and long-term (years six through fifteen) system impacts
due to customer load. The RTEP analysis ensures that all North American Electric Reliability
Corporation (“NERC”), PJM, and local reliability standards are met. When PJM identifies a
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“Time series” data is real time data, time stamped, and recorded throughout the period.
16
reliability or market efficiency issue, various parties are able to submit proposed solutions to the
issue. PJM will then select a solution and that party becomes obligated to fund and construct the
project by the service date established by PJM.
The PJM load forecasting and analysis process is explained in PJM Manual 19. This
includes the process to create the 15-year monthly peak forecasts for the entire PJM region. The
load forecast serves as the input to the transmission planning studies. The forecasts are
produced every year and released around January. With forecast data incorporated, the PJM
study process takes into account a number of additional factors when determining project needs.
These factors include: expected demand response; expected transfers; generation
additions/retirements; reactive resource capability; expected service dates of new or modified
transmission facilities; and duration or timing of known transmission outages. Projects will be
identified due to capacity needs as well as for market efficiency reasons. Market efficiency
projects consider energy forecasts, fuel and emissions costs, and various other sensitivities.
2.5.1. Transmission Planning Impacts from AMI
Reductions associated with AMI system-enabled programs are one factor among many
factors that affects hourly metered load data. As customers take advantage of demand response
programs and support reducing peak demand, the need for new transmission projects may be
altered. There are many additional factors, however, which determine the need for a
transmission project. For example, system voltage, thermal, stability, load deliverability,
generation deliverability, and congestion analyses criteria are all considered when determining
project needs. In addition, demand response resources that participate in PJM base residual and
incremental auctions are included in various power flow studies and can mitigate or delay the
need for transmission upgrades.
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2.6. System Performance
BGE is continually monitoring the electric grid to deliver safe and reliable electricity to
all customers. In addition to responding to day-to-day operational conditions such as loading
concerns and outages, BGE invests significant capital to maintain and improve the reliability of
the electric distribution system. Within the distribution level voltages (4kV – 34kV), capital
investments in infrastructure to improve reliability are included in the System Performance
category, which consists of a wide range of programs to meet increasingly robust reliability
goals. The purpose and scope of these programs can include reconfiguring the electric system,
selectively undergrounding overhead circuits, upgrading aging infrastructure, and leveraging
current technologies to enhance system performance.
2.6.1. AMI Impact on System Performance
AMI positively impacts the System Performance category. For example, before AMI,
BGE would traditionally only become aware of customer voltage issues when contacted directly
by the customers. However, with the inception of the Low Voltage Mitigation program within
the System Performance category, BGE is able to leverage AMI to obtain meter data and
proactively identify customers experiencing low voltage issues on the BGE distribution system.
Remediation solutions are then engineered, designed, and constructed to address the identified
issues.
Additionally, the System Performance category programs currently require routine
analysis to identify and prioritize each program’s annual work plan. While necessary and
altogether beneficial, the analysis can be time consuming. With the implementation of AMI,
BGE will be able to leverage the associated reliability data through its BIDA initiatives. With
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the additional reliability data, BGE will be able to more swiftly and effectively optimize each
program’s annual work plan.
3. USE OF THE AMI SYSTEM TO FURTHER IMPROVE THE EFFICIENCY AND
EFFECTIVENESS OF THE DISTRIBUTION NETWORK
An AMI system is the backbone infrastructure required to support many modern
technologies designed to improve the efficiency and effectiveness of the distribution network.
BGE completed its deployment of an AMI system in September 2015 and has already deployed a
number of programs that utilize the AMI system technology to drive efficiencies, increase
productivity, and improve services for customers. Over the next five years, BGE will
investigate, develop, and deploy a variety of additional technologies that depend upon the AMI
system in an effort to further improve the level of service for customers. This section of the Plan
discusses these existing and ongoing efforts of BGE.
3.1. BGE PeakRewardsSM
Enhancement Program
The BGE PeakRewardsSM
program initiated an enhancement project in November of
2015 to evaluate the working condition and functionality of demand response hardware installed
on customers’ air conditioning equipment. Under this enhancement project, BGE identifies
potential non-operable devices and schedules inspections by analyzing AMI data. Field
inspectors check demand response equipment for correct wiring, firmware, physical damage,
tampering, age, condition, and overall functionality. Any device issues are corrected or the
customer is removed from the PeakRewardsSM
program. Through this enhancement program,
BGE better ensures that the credits paid to participating customers will produce the expected
demand reduction when the program is activated. The PeakRewardsSM
Enhancement program,
enabled by AMI, allows BGE to be confident in the amount of load that can be controlled during
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a demand response event. This allows more effective project deferral decisions, due to local load
control, to be made.
Of the 13,056 inspections completed to date in the enhancement program on
PeakRewardsSM
air conditioning switches, the program vendor has provided an assessment based
upon devices inspected: 60% pass inspection with no observable malfunctions or installation
issues. Additionally, the program vendor has concluded that 27% have been observed
“tampered,” meaning that the PeakRewardsSM
device has been disconnected, 4.6% of devices
have been observed disconnected or missing due to installation of new HVAC equipment, and
the remaining 8% which fail inspection are due to physical damage, incorrect wiring, equipment
malfunctioning, or the consumer actually requests to be removed from the program at time of the
inspection. The inspection of potential non-operable devices allows BGE to identify and correct
equipment malfunction. This ensures the PeakRewardsSM
program is able to deliver the
expected demand response levels.
3.2. Remote Meter Reading and Remote Connection
The AMI system enables BGE to read and process meter usage data remotely, which
reduces labor, vehicle, and IT costs. Such capability also helps reduce the number of estimated
bills issued to customers.
Another benefit of the AMI system is the ability to remotely connect/disconnect electric
service, which reduces time and expense by eliminating otherwise required truck rolls. Further,
as a result of the technology, BGE can more efficiently respond to customer requests to initiate
or disconnect electric service.
3.3. Outage Management System – AMI System Integration
The outage management system (“OMS”) is the tool used by operating personnel at BGE
to identify customer outages and coordinate day-to-day operation of the distribution system. The
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system provides operating personnel with a model of the system as it currently exists in the field.
Having a current system model allows accurate and efficient operating decisions to be made
during outage events and other adverse operational conditions.
Historically, OMS would predict service outages using only customer outage calls. The
system would then take the calls associated with certain customers and determine the most likely
protective device that operated. With the OMS and AMI system integration, the ability to
identify outages from real-time data better enables significant operational improvements.
As a result of the AMI system, some outages can be detected before a call is even
received. This capability enables BGE to proactively respond to outages sooner than otherwise
possible, and this effectively reduces the outage restoration time. In addition, the AMI data
provides more information from which the cause of an outage can be predicted. This allows
BGE personnel to more accurately respond to outages. Customers also benefit as the outage
restoration time is reduced.
3.3.1. Restoration Verification
OMS automatically pings AMI meters to verify restoration times. Unsolicited power-on
responses received from the AMI meters can also be processed. The Restoration Verification
functionality allows power-on communications from individual AMI meters to appear as a
condition in the OMS viewer. By enabling OMS to automatically communicate with meters to
verify that the meter is working, BGE can verify that no nested outages exist, ultimately saving
customer outage minutes and unnecessary crew time.13
13
A nested outage is when two protective devices in series operate. The service operator is sent to the upstream
device to restore power and then when power is restored, the event is closed but the customers downstream of the
second device that operated are still left without power. Normally, another event is started and another service
operator would need to mitigate the second device outage resulting in longer outages times for the downstream
customers.
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3.3.2. Automatic Restore Time Adjustment and Predicted Service Outage
Verification
With the increased functionality and connectivity of the AMI network, the OMS system
is able to automatically adjust the restoration time to the time when AMI indicates the power has
been restored. The field crews currently input the restoration time manually, and this input
method can be subject to human error. Having the outage and restoration times validated against
the AMI data allows outage durations to be accurate, resulting in a reduction of the amount of
outage correction effort that is needed following a storm event.
In addition to adjusting restoration times, OMS is also able to automatically ping “single
no light” jobs to verify the status of the meter and determine if the outage is due to BGE or
customer equipment.14
If the automatic ping results in a response, OMS is able to remotely
detect that the meter is functioning and determine that the cause of the outage is on the customer
side of the meter. This additional information through the AMI system allows the dispatcher to
quickly review and close the job and dedicate resources to appropriate outage jobs.
Automatically verifying the status of single no light jobs avoids the need for additional resources
to investigate the outage, most likely through a field call to the customer’s premise.
3.3.3. OMS Functionality Currently Being Tested
In addition to the above functionalities being leveraged by BGE to improve the OMS and
response to customer outages, BGE is testing enhancements to its predicted device outage
verification capability. By being able to better pinpoint the predicted device outage, the outage
restoration effort can be conducted more efficiently. Repair crews are more likely to be
14
A “single no light” job is a single customer outage. This type of outage occurs due to damage on the secondary
loop or bus supplying the customer premise. Repair crews attempt to identify and correct all damage during the
initial restoration effort. The possibility for a customer to inadvertently be left out of service due to secondary
damage following repairs to the primary system is possible. It is more effective to identify and correct these issues
while the crew is still in the area conducting restoration efforts.
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dispatched to investigate the direct source of the problem. Another feature of AMI that is being
tested is for OMS to detect the AMI meter’s last gasp message following a power outage.
Receiving the last gasp can help create a predicted outage map that can be used for restoration
planning efforts.
3.4. Energy Theft Program
The energy theft program improves safety for employees, customers, and the general
public as well as helps ensure that those who receive service from BGE are financially
responsible. Prior to the deployment of the AMI system, many instances of meter tampering and
theft went undetected. With the AMI system, BGE is now able to detect, investigate, and
respond to potential theft circumstances in a more timely fashion. This is achieved through the
implementation of a data analytics tool that is able to identify non-operating meters and network
equipment. As a result of the analytics produced through the BIDA initiative, BGE is able to use
information from AMI meters to identify and address potential meter tampering and theft. Theft
detection reduces the amount of energy stolen, helps make system conditions safer, and has a
positive effect on the equitably distributing cost of electric service.
3.5. Distribution Automation
Distribution Automation (“DA”) is an advanced centralized control system used to
minimize the impact of faults that occur on the distribution system. The DA system consists of
electronic automatic reclosers installed in the field. The DA head-end control system, along with
a communication system, enables an automatic restoration scheme to be implemented. The DA
system improves the customer experience by reducing the number of transient faults that become
sustained outages (e.g., falling tree limbs on overhead lines that burn clear). The DA system also
reduces the number of customers impacted from an event by sectionalizing the system into
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smaller segments. Following an outage, electronic reclosers automatically isolate the fault, and
the DA system then coordinates recloser operations to quickly reconfigure the circuit and restore
unaffected sections to minimize the number of customers impacted by the outage. BGE’s DA
system operates on a single phase basis, limiting the interruption to customers on only the faulted
phases. There are approximately 3,000 automatic reclosers currently in service on the BGE
system. In 2016, the DA system saved approximately 2.6 million customer interruptions.
3.5.1. DA Communication System – Leveraging the AMI Provider System
The existing DA wireless communication network relies on 900MHz point-to-point radio
communication from master stations across the BGE territory to radios integrated into individual
recloser controllers. BGE plans to leverage its Smart Grid AMI Network Provider for the
deployment of its next-generation DA network. BGE also plans to leverage the AMI network for
the management of the DA radio devices. The new DA network will utilize wireless mesh
technology and will feature modern, multi-layer security features. BGE is starting the
deployment of the new DA network in 2017 and plans to complete the deployment in 2021.
In the future, BGE is likely to consider leveraging the new DA network to handle the
wireless communications of additional devices such as automated remote fault indicators,
secondary voltage regulating devices, and DER. As additional line sensing devices are installed
and communicate back to a central system, additional customer benefits will be achieved. For
example, the addition of fault indicators with communications capability will allow BGE to
improve outage identification and dispatch, reducing Customer Average Interruption Duration
Index (“CAIDI”). The new communications network may also allow monitoring and control of
secondary line voltage regulating devices and customer DER which may help further improve
reliability.
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3.6. Conservation Voltage Reduction
Conservation Voltage Reduction (“CVR”) is a technique for improving the efficiency of
the electric distribution system by optimizing voltage levels, within the limits prescribed by
COMAR 20.50.07.02, on the circuits that run from substations to homes and businesses. Lower
voltage levels result in customers using less energy, which leads to lower customer bills. By
reducing the need to generate additional energy at power plants, CVR also helps to reduce
carbon emissions.
The AMI system is one of the enablers for the effective implementation of BGE’s
industry-leading CVR program. More specifically, the AMI system provides customer voltage
data that can be used to optimize voltage levels in a manner that maximizes customer savings
while ensuring voltages are maintained within the COMAR limits.
During the next five years, BGE will continue to investigate opportunities to further
enhance its CVR program. For example, one promising application is the further use of data
obtained from CVR and AMI systems and development of voltage analytics to dynamically
adjust CVR voltage targets based on system conditions. Further, BGE is looking to incorporate
newly available data to improve its planning process for the addition of reactive power resources.
3.7. Business Intelligence and Data Analytics
Over the next five years, BGE will focus on translating accumulated data into solutions
that improve the efficiency and effectiveness of the distribution network. The following
subsections highlight the various applications being investigated and implemented by BGE over
the next five years.
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3.7.1. Transformer and Line Equipment Sizing
The availability of AMI data will assist BGE in determining the optimal sizing of
transformer and line equipment in the future. Consistent with other utilities across the nation,
BGE does not meter customer service transformers. In order to estimate transformer utilization,
BGE currently leverages a legacy system that utilizes a correlation between customer kWh
consumption and peak demand to estimate the peak kVA demand on the customer service
transformer. This information is used to estimate available transformer capacity before adding
new customers to the system. Knowing the actual peak kVA demand on a transformer by
aggregating meter data from AMI, however, may allow more load to be added to an existing
transformer. In the past, another transformer or upsizing the existing transformer may have been
required if the equipment was estimated to be fully utilized.
AMI information also helps to model the placement of load across the distribution
circuits. Because a variety of customer types and load shapes exist across the BGE service
territory, the accuracy of the predicted component loading obtained using the legacy system can
be fairly limited in certain circumstances. AMI data includes the kWh demand and time of use
information for all customers. By leveraging AMI data, the peak hourly demand for each
customer service transformer could be calculated based upon the connected customer meters and
used in the project prioritization process.
The AMI data will also allow a review of customer load estimation assumptions further
allowing for improved equipment sizing. Having the correct size transformer initially installed
avoids follow-up work and potential system issues. A better understanding of the load profiles
on the equipment can also lead to improved health monitoring. As equipment becomes
overloaded, proactive measures can be taken to address the overload. Equipment can be
26
upgraded to avoid premature failure. It may also be possible to reconfigure the system to shift
load to equipment that does have the necessary capacity. Ultimately, AMI can allow better
utilization of existing infrastructure to be achieved and potentially allow project deferment.
3.7.2. Power Quality Assessment
BGE’s current process is to reactively respond to customer power quality (“PQ”)
complaints. After a customer opens a PQ case with BGE, PQ meters can be installed for a
limited time at a customer’s meter or service transformer. The installed monitoring device will
capture and record data on any PQ events for additional analysis. A method to proactively
identify issues did not previously exist before the AMI system was deployed. AMI meters
monitor voltage and capture average voltage data as well as certain voltage sag/swell events.
Recorded PQ information can then be reported back to the utility.
Additional information from the AMI system may allow customer issues to be
proactively addressed. Reports can be run to identify customers experiencing sustained low or
high voltages. These issues can be further investigated and addressed before the customer
experiences any noticeable power quality issues. Similar reports can be created to identify
customers experiencing large numbers of momentary outages or sag/swell events in an effort to
proactively identify and remediate poor performing areas of the system.
3.7.3. Network Connectivity
BGE maintains an electrical network connectivity model down to the individual
customer, which includes the meter to transformer and transformer to phase relationship. As
with any data set, there is occasionally inaccurate or incomplete data. Examples of these
inaccuracies would be meters mapped to the wrong transformer, meters not mapped to any
transformer, or transformers mapped to the wrong phase on the feeder. These inaccuracies
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become issues during outage detection and restoration response. In addition, a complete and
accurate network connectivity model is necessary to perform advanced analytics on the grid.
Without accurate data, it would be difficult to conduct high value analytics and produce
meaningful conclusions.
Before AMI, it was not feasible to detect and correct network connectivity errors from
readily available information. Meter to transformer relationship errors would have often gone
undiagnosed. With the additional data provided by the AMI, however, a number of different
methods to determine inaccuracies and recommend corrections now exist.
The first is geospatial analysis, analyzing the physical proximity of the meter to the
transformer. Distances that are exceptionally long might indicate an error. Another method is to
analyze outage data from multiple meters on a single transformer. This analysis would compare
outage and restoration event timestamps from the smart meters mapped to the transformer and
determine if there are any abnormalities (i.e., one of several meters does not show an outage at
the same time as the other meters). The final method is to compare the voltage profile data for
all meters on a transformer and determine if there is one that is dissimilar to the others. A
combination of these methods can be used to identify inaccuracies and suggest corrections.
A direct operational benefit from the improved network connectivity case is enhanced
storm response. As outage information comes to the outage management system (via smart
meter alerts or customer reports) single outage events can be analyzed with the connectivity
model and other grid sensors to determine the size and scope of the outage. When a large area is
restored and damage still exists on the downstream system, those customers still out will be
immediately identified and restored while the crews are still in the area.
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3.7.4. Load Forecasting
BGE currently uses a top down model of load forecasting for the individual feeders on
the distribution system. By leveraging circuit metering at the substation (head of feeder), future
new customer loads, and a weather normalization algorithm, BGE forecasts the load for each
feeder for the next several years. These forecasts currently lack granular detail of loading along
the feeder and an in depth understanding of each customer’s contribution to the feeder peak load.
Through AMI data, BGE can forecast load down to a more granular level along the
feeder, as opposed to just at the head of the feeder. This leads to greater understanding of
loading along each segment, the drivers for yearly load increases/decreases, and prediction of
potential thermal overloads. The individual customer loads would be able to be aggregated to
their segment along the feeder to understand the loading. In addition, the AMI data allows the
analytics to layer in customers with DER. The additional transparency and understanding of
how the customer DER affects the loading along the feeder can greatly improve the identification
of true loads and the projects needed to support system reliability.
Through enhanced load forecasting, BGE has a better understanding of the scope and
timing of potential thermal overloads. Better understanding allows tighter project planning
criteria. For example, without AMI data, forecasted overloads may require significant
reconductoring of a feeder, a new feeder or a new substation. With a more granular
understanding of the loads along the feeder, and the potential overloads, a more surgical solution
may be possible for addressing issues. Reconductoring a specific section of the circuit,
transferring a specific set of customers to adjacent feeders, or strategic placement of battery
storage along the feeder may be possible. In addition, the increased accuracy of when these
overloads are predicted to occur allows BGE to deploy solutions closer to when they are needed.
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3.7.5. Overloaded Equipment Transparency
All equipment on the electric system is sized to fit the voltage and loading requirements
of the customers supplied. A buffer is normally applied to equipment sizing because the needed
data is provided by the customer and typically only accounts for their current needs at the time of
initial installation. If a residential community gets developed or a commercial customer adds
additional machines, load could increase beyond the initial load usage data. Properly sizing
equipment for ultimate needs may be more cost effective and prevent premature equipment
failure due to overload.
AMI data, along with future advanced analytic tools, will allow BGE to aggregate energy
usage to the upstream equipment to determine if a device is overloaded or if a new customer
provided improper load information. BGE would then be able to proactively develop a plan to
address the concern. It is ideal to proactively replace overloaded equipment or to move load
before an outage is experienced due to equipment failure. Reconfiguring the electric
infrastructure is an effective means to maximize existing infrastructure and defer the cost of
upgrading equipment while still providing safe and reliable electricity.
3.7.6. Momentary Data Analysis
BGE focuses a majority of its reliability resources to address areas that experience
sustained outages, responding to issues as they occur retroactively. With AMI and advanced
analytics, BGE will have the ability to effectively leverage momentary outages and identify areas
that are becoming at risk for future sustained outages. A momentary outage or transient fault is
any fault that clears itself given a small amount of time. Examples include a tree branch
brushing the lines due to high winds or wildlife making contact and falling clear of the
equipment.
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Before the AMI system, the only way BGE would be aware of a protective device
reclosing due to a transient fault would be either a customer complaint of excessive momentary
outages or a reclosing device with communication capabilities reporting the event. Analyzing
momentary outage data provided by the AMI network will enable BGE to identify areas showing
signs of potential reliability concerns. An inspection or other proactive measures can then be
taken to prevent possible future sustained outages. Targeted tree trimming, equipment integrity
inspections, and system redesigns are all options available to BGE. The overall customer
experience would be improved by addressing momentary outage issues, as issues causing
momentary outage may turn into a sustained outage down the road if not addressed.
3.7.7. Voltage Var Optimization
AMI voltage data can be used to evaluate the performance of the CVR/Voltage Var
Optimization (“VVO”) algorithm and to identify opportunities for further refinement of CVR
operating parameters. Examples include calculation of optimal voltage set points for each
circuit, identification of extensive device operations in search of an optimal operating point, and
identification of devices that are not operating as expected. AMI data can also be used to
optimize the operation of the CVR algorithm and assure operation within the prescribed voltage
limits.
In addition, AMI data can be used to recommend optimal size and location for placement
of new devices that could further optimize the operation of the CVR algorithm, and for
calculation of optimal tap positions for Non-LTC transformers.
4. USE OF THE AMI SYSTEM TO FURTHER IMPROVE THE EFFICIENCY AND
EFFECTIVENESS OF DISTRIBUTED ENERGY RESOURCES
INTERCONNECTED TO THE DISTRIBUTION NETWORK
DER, including solar, wind, and battery storage systems, have become more cost
effective in recent years. Many customers are taking advantage of state and federal incentives to
31
install DER systems. The new DER systems are able to offset a portion of the customer energy
usage, but most systems do not produce a significant offset at the time of the system peak. The
following Figure 7 provides an overview of the volume of DER systems installed on the BGE
electric distribution system:
Figure 7: Volume of DER Systems Installed on the BGE Electric System
The effects of DER can be challenging for utilities. The electric grid was originally
designed for uni-directional power flow, and DERs have the potential to create bi-directional
power flow. Regardless of the challenges, the utility can help to maximize benefits from DER
installations when they are incorporated into their distribution planning efforts.
The AMI system helps the utility to manage the impacts of DER on the electric grid by
providing a wealth of data that can be used for operating and planning purposes. Having more
metered locations throughout the electric system, with data available in near real-time, allows the
utility to better assess and monitor the system conditions. The effects of DER to the grid cannot
32
be fully determined without having good system performance data at the customer level. AMI is
able to provide some of the needed customer data to help monitor the impacts of DER.
4.1. DER System Impact Challenges
There are practical challenges the utility must address when integrating DER systems.
DERs must be operated in a safe and reliable manner without compromising the existing
infrastructure or quality of service to nearby customers. Utilities must design, construct, operate,
maintain, and upgrade the distribution system to be able to supply the full requirements of the
connected customers at any time, whether or not the local DER is available. DER systems are
typically intermittent resources and may contribute to the complexities of operating and
maintaining the electric system. A classic example is the peak loads the utility might see during
the overnight hours on a bitter cold February night. While significant solar capability exists on
that feeder, those DER resources are not available in the absence of sunlight. Without DER
systems operating reliably at the required time periods, system capacity must still exist to meet
peak loads and ensure key operating measures like voltage and frequency are within operating
limits.
When evaluating the impact of DER, it is important to consider the true potential load on
the distribution system to ensure proper design and operation of the grid. The true load on a
circuit may be masked by the DER. Most DER is not monitored or managed by the utility and
may become disconnected at any time. AMI data can be used to calculate true loads by
combining customer load curves and estimated DER load curves. Impact of DER, during critical
time periods, on customer loads and voltage can also be more easily identified with AMI data.
The need for system enhancements or project deferrals can be verified by considering true
equipment loading.
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4.2. Benefits of DER
The installation of DER technology has the potential to generate many benefits to BGE
customers and stakeholders. Line losses may be reduced because generation will be closer to the
load. DER can also be designed to separate from the grid in times of emergencies in order to run
critical customer load.15
Energy storage DER systems can store off-peak energy and deliver the
stored energy to the grid at peak.16
The AMI system has the potential to allow improved DER
system modeling which may allow increased penetration of DER devices and reduced system
planning criteria margins.
4.3. Smart Inverters
Smart inverters provide advanced functions that support grid reliability. A smart inverter
uses digital architecture, bidirectional communications, and robust software infrastructure to
provide dynamic reactive and real power support. Advanced functions like frequency ride-
through, ramp rate control, and communication allow the utility to better integrate DER. These
functions can be used to mitigate issues related to high penetration levels of DER on the
distribution system. Customers may be able to install larger systems while maintaining reliable
voltage levels. Having better control of the DER system output can allow grid operations to
better manage system reliability. In the future, with two-way communications with the
customer, the utility will be able to coordinate operations with the smart inverters, possibly
through the AMI network. This coordination will allow DER penetration to increase further,
which may further improve grid reliability.
15
Solar PV is an exception to this for most installations as national codes and standards require the PV system to
separate from the grid and stop production on loss of the utility supply, for safety and the protection of the local
installation and adjacent customer equipment.
16 Energy storage systems can take advantage of off-peak energy rates. At peak the stored energy can be released,
resulting in a reduced customer demand. These systems are typically applied on large industrial and commercial
customers, as demand charge savings can be substantial.
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4.4. Energy Storage
Energy storage technologies include batteries, flywheel, compressed air, thermal storage,
and pumped hydropower. Storage can be used to provide power to the electric grid when
needed, which increases reliability and resiliency. The use of battery storage has been a topic of
particular interest recently because of improved technology and reduced costs. Having energy
storage available throughout the system creates the ability to shift peak loads and participate in
the wholesale markets. As regulations allow, storage may be used to integrate more DER,
especially solar and wind, onto the electric grid and reduce the issues of intermitted energy
resources.
4.5. Benefits of AMI for DER
The amount of DER that can be safely and reliably installed on the distribution system is
referred to as the hosting capacity. Utilities determine the hosting capacity of a circuit or
substation by analyzing the effects of the DER on the circuit at various locations. The DER has
the potential to negatively impact load, voltage, or the protection systems on a circuit and hosting
capacity tries to create a high level view of what can be theoretically interconnected.
Advanced computer models, using AMI data, will allow BGE to predict the combined
impact of aggregated DER to feeders, transformers, and other grid components. AMI allows
improved data and data models. Modeling the type, location, and time based characteristics of
DER and customer load, allows the utility to analyze distribution components and determine if a
problem exists or could be expected. For example, by monitoring voltages at the customer level,
BGE can verify the effects of adding DER to the system. If a localized area is currently
experiencing borderline high voltage, a DER installation may exacerbate the issue, and therefore
be denied.
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Future BIDA systems can use AMI data to locate unaccounted for DER interconnections.
The system models can be verified and improved by comparing model results with customer
real-time data. Costly electric system infrastructure issues can occur with a poorly coordinated
rollout of DER systems. Using AMI data can allow customer satisfaction to be maximized as
system issues will be avoided or identified quickly for correction.
Interconnection studies may also be improved by AMI. Some DER interconnections can
be approved during the screening process while others require a detailed study. AMI provides
time series customer data that can be used to enhance the screening process. Future tools may be
able to automatically study the impact of the proposed DER, and AMI will be a key data input.
With advanced tools, suspect DER applications can be flagged for additional review. Border line
voltage levels or operational concerns may trigger additional analysis. For example, the AMI
data can be used to flag customers currently operating near the upper limits of the voltage
bandwidth. Installing DER near these customers may potentially exacerbate or create customer
voltage issues.
5. CONCLUSION
BGE’s investment in an AMI system has laid the foundation for the deployment of
modern technologies – some of which have yet to even be imagined – that will improve system
reliability, enhance the customer experience, and afford customers additional opportunities to
save money on their utility bills. As part of the Company’s strategy for the next five years, BGE
will continue to investigate innovative ways to serve its customers and take advantage of the
AMI system backbone infrastructure. In so doing, however, BGE must always remain
committed to its core obligation to provide safe and reliable electric and gas service to its
customers. Accordingly, the Company must continue to take a measured and balanced approach
to distribution system planning to ensure that its core obligations are not compromised.